This section is intended to introduce selected aspects of the art, which may be associated with various embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Field of the Invention
The present disclosure relates to the field of well completions and workover operations. More specifically, the present disclosure relates to a tractor system used for advancing a tubular body into or out of a wellbore. The tractor system may, in one aspect, be used in connection with translating a jetting hose relative to a surrounding tubular carrier body that is part of a hydraulic jetting assembly.
Discussion of Technology
In the drilling of an oil and gas well, a near-vertical wellbore is formed through the earth using a drill bit urged downwardly at a lower end of a drill string. After drilling to a predetermined bottomhole location, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation penetrated by the wellbore. Particularly in a vertical wellbore, or the vertical section of a horizontal well, a cementing operation is conducted in order to fill or “squeeze” the entire annular volume with cement along part or all of the length of the wellbore. The combination of cement and casing strengthens the wellbore and facilitates the zonal isolation, and subsequent completion, of certain sections of potentially hydrocarbon-producing pay zones behind the casing.
Within the last two decades, advances in drilling technology have enabled oil and gas operators to economically “kick-off” and steer wellbore trajectories from a generally vertical orientation to a generally horizontal orientation. The horizontal “leg” of each of these wellbores now often exceeds a length of one mile. This significantly multiplies the wellbore exposure to a target hydrocarbon-bearing formation (or “pay zone”). For example, for a given target pay zone having a (vertical) thickness of 100 feet, a one mile horizontal leg exposes 52.8 times as much pay zone to a horizontal wellbore as compared to the 100-foot exposure of a conventional vertical wellbore.
FIG. 1A provides a cross-sectional view of a wellbore 4 having been completed in a horizontal orientation. It can be seen that a wellbore 4 has been formed from the earth surface 1, through numerous earth strata 2a, 2b, . . . 2h and down to a hydrocarbon-producing formation 3. The subsurface formation 3 represents a “pay zone” for the oil and gas operator. The wellbore 4 includes a vertical section 4a above the pay zone, and a horizontal section 4c. The horizontal section 4c defines a heel 4b and a toe 4d and an elongated leg there between that extends through the pay zone 3.
In connection with the completion of the wellbore 4, several strings of casing having progressively smaller outer diameters have been cemented into the wellbore 4. These include a string of surface casing 6, and may include one or more strings of intermediate casing 9, and finally, a production casing 12. (Not shown is the shallowest and largest diameter casing referred to as conductor pipe, which is a short section of pipe separate from and immediately above the surface casing.) One of the main functions of the surface casing 6 is to isolate and protect the shallower, fresh water bearing aquifers from contamination by any wellbore fluids. Accordingly, the conductor pipe and the surface casing 6 are almost always cemented 7 entirely back to the surface 1.
The process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. In some instances, the final string of casing 12 is a liner, that is, a string of casing that is not tied back to the surface 1. The final string of casing 12, referred to as a production casing, is also typically cemented 13 into place. In the case of a horizontal completion, the production casing 12 may be cemented, or may provide zonal isolation using external casing packers (“ECP's), swell packers, or some combination thereof.
Additional tubular bodies may be included in a well completion. These include one or more strings of production tubing placed within the production casing or liner (not shown in FIG. 1A). In a vertical well completion, each tubing string extends from the surface 1 to a designated depth proximate the production interval 3, and may be attached to a packer (not shown). The packer serves to seal off the annular space between the production tubing string and the surrounding casing 12. In a horizontal well completion, the production tubing is typically landed (with or without a packer) at or near the heel 4b of the wellbore 4.
In some instances, the pay zone 3 is incapable of flowing fluids to the surface 1 efficiently. When this occurs, the operator may install artificial lift equipment (not shown in FIG. 1A) as part of the wellbore completion. Artificial lift equipment may include a downhole pump connected to a surface pumping unit via a string of sucker rods run within the tubing. Alternatively, an electrically-driven submersible pump may be placed at the bottom end of the production tubing. Gas lift valves, hydraulic jet pumps, plunger lift systems, or various other types of artificial lift equipment and techniques may also be employed to assist fluid flow to the surface 1.
As part of the completion process, a wellhead 5 is installed at the surface 1. The wellhead 5 serves to contain wellbore pressures and direct the flow of production fluids at the surface 1. Fluid gathering and processing equipment (not shown in FIG. 1A) such as pipes, valves, separators, dehydrators, gas sweetening units, and oil and water stock tanks may also be provided. Subsequent to completion of the pay zone(s) followed by installation of any requisite downhole tubulars, artificial lift equipment, and the wellhead 5, production operations may commence. Wellbore pressures are held under control, and produced wellbore fluids are segregated and distributed appropriately.
Within the United States, many wells are now drilled principally to recover oil and/or natural gas, and potentially natural gas liquids, from pay zones previously thought to be too impermeable to produce hydrocarbons in economically viable quantities. Such “tight” or “unconventional” formations may be sandstone, siltstone, or even shale formations. Alternatively, such unconventional formations may include coalbed methane. In any instance, “low permeability” typically refers to a rock interval having permeability less than 0.1 millidarcies.
In order to enhance the recovery of hydrocarbons, particularly in low-permeability formations, subsequent (i.e., after perforating the production casing or liner) stimulation techniques may be employed in the completion of pay zones. Such techniques include hydraulic fracturing and/or acidizing. In addition, “kick-off” wellbores may be formed from a primary wellbore in order to create one or more new directionally or horizontally completed boreholes. This allows a well to penetrate along the plane of a subsurface formation to increase exposure to the pay zone. Where the natural or hydraulically-induced fracture plane(s) of a formation is vertical, a horizontally completed wellbore allows the production casing to intersect, or “source,” multiple fracture planes. Accordingly, whereas vertically oriented wellbores are typically constrained to a single hydraulically-induced fracture plane per pay zone, horizontal wellbores may be perforated and hydraulically fractured in multiple locations, or “stages,” along the horizontal leg 4c. 
FIG. 1A demonstrates a series of fracture half-planes 16 along the horizontal section 4c of the wellbore 4. The fracture half-planes 16 represent the orientation of fractures that will form in connection with a perforating/fracturing operation. According to principles of geo-mechanics, fracture planes will generally form in a direction that is perpendicular to the plane of least principal stress in a rock matrix. Stated more simply, in most wellbores, the rock matrix will part along vertical lines when the horizontal section of a wellbore resides below 3,000 feet, and sometimes as shallow as 1,500 feet, below the surface. In this instance, hydraulic fractures will tend to propagate from the wellbore's perforations 15 in a vertical, elliptical plane perpendicular to the plane of least principle stress. If the orientation of the least principle stress plane is known, the longitudinal axis of the leg 4c of a horizontal wellbore 4 is ideally oriented parallel to it such that the multiple fracture planes 16 will intersect the wellbore at-or-near orthogonal to the horizontal leg 4c of the wellbore, as depicted in FIG. 1A.
The desired density of perforated and fractured intervals within the pay zone 3 along the horizontal leg 4c is optimized by calculating:                the estimated ultimate recovery (“EUR”) of hydrocarbons each fracture will drain, which requires a computation of the Stimulated Reservoir Volume (“SRV”) that each fracture treatment will connect to the wellbore via its respective perforations; less        any overlap with the respective SRV's of bounding fracture intervals; coupled with        the anticipated time-distribution of hydrocarbon recovery from each fracture; versus        the incremental cost of adding another perforated/fractured interval.        
The ability to replicate multiple vertical completions along a single horizontal wellbore is what has made the pursuit of hydrocarbon reserves from unconventional reservoirs, and particularly shales, economically viable within relatively recent times. This revolutionary technology has had such a profound impact that currently Baker Hughes Rig Count information for the United States indicates only about one-fourth (26%) of wells being drilled in the U.S. are classified as “Vertical”, whereas the other three-fourths are classified as either “Horizontal” or “Directional” (62% and 12%, respectively). That is, horizontal wells currently comprise approximately two out of every three wells being drilled in the United States.
The additional costs in drilling and completing horizontal wells as opposed to vertical wells is not insignificant. In fact, it is not at all uncommon to see horizontal well drilling and completion (“D&C”) costs top multiples (double, triple, or greater) of their vertical counterparts. Depending on the geologic basin, and particularly the geologic characteristics that govern such criteria as drilling penetration rates, required drilling mud rheology, casings design and cementation, etc., significant additional costs for drilling and completing horizontal wells include those involved in controlling the radius of curvature of the kick-off, and guidance of the bit and drilling assembly (including MWD and LWD technologies) in initially obtaining, then maintaining the preferred at-or-near horizontal trajectory of the wellbore 4 within the pay zone 3, and the overall length of the horizontal section 4c. The critical process of obtaining wellbore isolation between frac stages, as with additional cementing and/or ECP's, are often significant additions to the increased completion expenses, as are costs for “plug-and-perf” or sleeve or port (typically ball-drop actuated) completion systems.
In many cases, however, the greatest single cost in drilling and completing horizontal wells is the cost associated with pumping the multiple hydraulic fracture treatments themselves. It is not uncommon for the sum of the costs of a given horizontal well's hydraulic fracturing treatments to approach, or even exceed, 50% of its total drilling and completion cost.
Complicating the planning of a horizontal wellbore are the uncertainties associated with fracture geometries within unconventional reservoirs. Many experts believe, based on analyses of real-time data from both tilt meter and micro-seismic surveys, that fracture geometries in less permeable, and particularly, more brittle, unconventional reservoirs can yield highly complex fracture geometries. That is, as opposed to the relatively simplistic bi-wing elliptical model perceived to fit most conventional reservoirs (and as shown in the idealistic rendition in FIG. 1A), fracture geometries in unconventional reservoirs can be frustratingly unpredictable.
In most cases, far-field fracture length and complexity is deemed detrimental (rather than beneficial) due to excessive fluid leak-off and/or reduced fracture width that can cause early screen-outs. Hence, whether fracture complexity (or, the lack thereof) enhances or reduces the SRV that the fracture network will enable the wellbore to drain is typically determined on a case-by-case (e.g., reservoir-by-reservoir) basis.
Thus, it is desirable, particularly in horizontal wellbore completions for tight reservoirs, to obtain greater control over the geometric growth of the primary fracture network extending perpendicularly outward from the horizontal leg 4c. It is further desirable to extend the length of the fracture network azimuth without significantly trespassing the horizontal pay zone 3 boundaries. Further, it is desirable to decrease the well density required to drain a given reservoir volume by increasing the effectiveness of the fracture network between wellbores through the use of two or more hydraulically-jetted mini-laterals along a horizontal leg. Still further, it is desirable to provide this guidance, constraint, and enhancement of SRV's by the creation of one or more mini-lateral boreholes as a replacement of conventional casing portals provided by the use of conventional completion procedures requiring perforations, sliding sleeves, and the like.
Accordingly, a need exists for a downhole assembly having a jetting hose and a whipstock, whereby the assembly can be conveyed into any wellbore interval of any inclination, including an extended horizontal leg. A need further exists for a hydraulic jetting system that provides for substantially a 90° turn of the jetting hose opposite the point of a casing exit, preferably utilizing the entire casing inner diameter as the bend radius for the jetting hose, thereby providing for the maximum possible inner diameter of jetting hose, and thus providing the maximum possible hydraulic horsepower to the jetting nozzle.
Additional needs exist that, in certain embodiments, are addressed herein. A need exists for improved methods of forming lateral wellbores using hydraulically directed forces, wherein the desired length of jetting hose can be conveyed even from a horizontal wellbore. Further, a need exists for a method of forming lateral boreholes off of a horizontal leg that assist in confining subsequent SRV's up to, but not significantly beyond, pay zone boundaries. Still further, a need exists to be able to convey the jetting hose in an uncoiled state, such that the bend radius within the production casing and along the whipstock is the tightest bending constraint the hose must satisfy.
Finally, a need exists for a tractor system that is able to translate a jetting hose into and out of a parent wellbore during hydraulic borehole formation, even many tens of feet, without uncoiling and re-coiling the hose.